1. Field of the Invention
The present invention relates generally to methods and systems for production of hydrocarbons, hydrogen, and/or other products from various hydrocarbon containing formations. Certain embodiments relate to in situ conversion of hydrocarbons to produce hydrocarbons, hydrogen, and/or novel product streams from underground hydrocarbon containing formations.
2. Description of Related Art
Hydrocarbons obtained from subterranean (e.g., sedimentary) formations are often used as energy resources, as feedstocks, and as consumer products. Concerns over depletion of available hydrocarbon resources have led to development of processes for more efficient recovery, processing and/or use of available hydrocarbon resources. In situ processes may be used to remove hydrocarbon materials from subterranean formations. Chemical and/or physical properties of hydrocarbon material within a subterranean formation may need to be changed to allow hydrocarbon material to be more easily removed from the subterranean formation. The chemical and physical changes may include in situ reactions that produce removable fluids, composition changes, solubility changes, phase changes, and/or viscosity changes of the hydrocarbon material within the formation. A fluid may be, but is not limited to, a gas, a liquid, an emulsion, a slurry and/or a stream of solid particles that has flow characteristics similar to liquid flow.
Examples of in situ processes utilizing downhole heaters are illustrated in U.S. Pat. Nos. 2,634,961 to Ljungstrom, 2,732,195 to Ljungstrom, 2,780,450 to Ljungstrom, 2,789,805 to Ljungstrom, 2,923,535 issued to Ljungstrom, and 4,886,118 to Van Meurs et al., each of which is incorporated by reference as if fully set forth herein.
Application of heat to oil shale formations is described in U.S. Pat. No. 2,923,535 to Ljungstrom and 4,886,118 to Van Meurs et al., both of which are incorporated by reference as if fully set forth herein. Heat may be applied to the oil shale formation to pyrolyze kerogen within the oil shale formation. The heat may also fracture the formation to increase permeability of the formation. The increased permeability may allow formation fluid to travel to a production well where the fluid is removed from the oil shale formation. In some processes disclosed by Ljungstrom, for example, an oxygen containing gaseous medium is introduced to a permeable stratum, preferably while still hot from a preheating step, to initiate combustion.
A heat source may be used to heat a subterranean formation. Electrical heaters may be used to heat the subterranean formation by radiation and/or conduction. An electrical heater may resistively heat an element. U.S. Pat. No. 2,548,360 to Germain, which is incorporated by reference as if fully set forth herein, describes an electrical heating element placed within a viscous oil within a wellbore. The heater element heats and thins the oil to allow the oil to be pumped from the wellbore. U.S. Pat. No. 4,716,960 to Eastlund et al., which is incorporated by reference as if fully set forth herein, describes electrically heating tubing of a petroleum well by passing a relatively low voltage current through the tubing to prevent formation of solids. U.S. Pat. No. 5,065,818 to Van Egmond, which is incorporated by reference as if fully set forth herein, describes an electrical heating element that is cemented into a well borehole without a casing surrounding the heating element.
U.S. Pat. No. 6,023,554 to Vinegar et al., which is incorporated by reference as if fully set forth herein, describes an electrical heating element that is positioned within a casing. The heating element generates radiant energy that heats the casing. A granular solid fill material may be placed between the casing and the formation. The casing may conductively heat the fill material, which in turn conductively heats the formation.
U.S. Pat. No. 4,570,715 to Van Meurs et al., which is incorporated by reference as if fully set forth herein, describes an electrical heating element. The heating element has an electrically conductive core, a surrounding layer of insulating material, and a surrounding metallic sheath. The conductive core may have a relatively low resistance at high temperatures. The insulating material may have electrical resistance, compressive strength and heat conductivity properties that are relatively high at high temperatures. The insulating layer may inhibit arcing from the core to the metallic sheath. The metallic sheath may have tensile strength and creep resistance properties that are relatively high at high temperatures.
U.S. Pat. No. 5,060,287 to Van Egmond, which is incorporated by reference as if fully set forth herein, describes an electrical heating element having a copper-nickel alloy core.
Combustion of a fuel may be used to heat a formation. Combusting a fuel to heat a formation may be more economical than using electricity to heat a formation. Several different types of heaters may use fuel combustion as a heat source that heats a formation. The combustion may take place in the formation, in a well and/or near the surface. Combustion in the formation may be a fireflood. An oxidizer may be pumped into the formation. The oxidizer may be ignited to advance a fire front towards a production well. Oxidizer pumped into the formation may flow through the formation along fracture lines in the formation. Ignition of the oxidizer may not result in the fire front flowing uniformly through the formation.
A flameless combustor may be used to combust a fuel within a well. U.S. Pat. Nos. 5,255,742 to Mikus, 5,404,952 to Vinegar et al., 5,862,858 to Wellington et al., and 5,899,269 to Wellington et al., which are incorporated by reference as if fully set forth herein, describe flameless combustors. Flameless combustion may be accomplished by preheating a fuel and combustion air to a temperature above an auto-ignition temperature of the mixture. The fuel and combustion air may be mixed in a heating zone to combust. In the heating zone of the flameless combustor, a catalytic surface may be provided to lower the auto-ignition temperature of the fuel and air mixture.
Heat may be supplied to a formation from a surface heater. The surface heater may produce combustion gases that are circulated through wellbores to heat the formation. Alternately, a surface burner may be used to heat a heat transfer fluid that is passed through a wellbore to heat the formation. Examples of fired heaters, or surface burners that may be used to heat a subterranean formation, are illustrated in U.S. Pat. Nos. 6,056,057 to Vinegar et al. and 6,079,499 to Mikus et al., which are both incorporated by reference as if fully set forth herein.
Coal is often mined and used as a fuel within an electricity generating power plant. Most coal that is used as a fuel to generate electricity is mined. A significant number of coal formations are, however, not suitable for economical mining. For example, mining coal from steeply dipping coal seams, from relatively thin coal seams (e.g., less than about 1 meter thick), and/or from deep coal seams may not be economically feasible. Deep coal seams include coal seams that are at, or extend to, depths of greater than about 3000 feet (about 914 m) below surface level. The energy conversion efficiency of burning coal to generate electricity is relatively low, as compared to fuels such as natural gas. Also, burning coal to generate electricity often generates significant amounts of carbon dioxide, oxides of sulfur, and oxides of nitrogen that are released into the atmosphere.
Synthesis gas may be produced in reactors or in situ within a subterranean formation. Synthesis gas may be produced within a reactor by partially oxidizing methane with oxygen. In situ production of synthesis gas may be economically desirable to avoid the expense of building, operating, and maintaining a surface synthesis gas production facility. U.S. Pat. No. 4,250,230 to Terry, which is incorporated by reference as if fully set forth herein, describes a system for in situ gasification of coal. A subterranean coal seam is burned from a first well towards a production well. Methane, hydrocarbons, H2, CO, and other fluids may be removed from the formation through the production well. The H2 and CO may be separated from the remaining fluid. The H2 and CO may be sent to fuel cells to generate electricity.
U.S. Pat. No. 4,057,293 to Garrett, which is incorporated by reference as if fully set forth herein, discloses a process for producing synthesis gas. A portion of a rubble pile is burned to heat the rubble pile to a temperature that generates liquid and gaseous hydrocarbons by pyrolysis. After pyrolysis, the rubble is further heated, and steam or steam and air are introduced to the rubble pile to generate synthesis gas.
U.S. Pat. No. 5,554,453 to Steinfeld et al., which is incorporated by reference as if fully set forth herein, describes an ex situ coal gasifier that supplies fuel gas to a fuel cell. The fuel cell produces electricity. A catalytic burner is used to burn exhaust gas from the fuel cell with an oxidant gas to generate heat in the gasifier.
Carbon dioxide may be produced from combustion of fuel and from many chemical processes. Carbon dioxide may be used for various purposes, such as, but not limited to, a feed stream for a dry ice production facility, supercritical fluid in a low temperature supercritical fluid process, a flooding agent for coal bed demethanation, and a flooding agent for enhanced oil recovery. Although some carbon dioxide is productively used, many tons of carbon dioxide are vented to the atmosphere.
Retorting processes for oil shale may be generally divided into two major types: aboveground (surface) and underground (in situ). Aboveground retorting of oil shale typically involves mining and construction of metal vessels capable of withstanding high temperatures. The quality of oil produced from such retorting may typically be poor, thereby requiring costly upgrading. Aboveground retorting may also adversely affect environmental and water resources due to mining, transporting, processing and/or disposing of the retorted material. Many U.S. patents have been issued relating to aboveground retorting of oil shale. Currently available aboveground retorting processes include, for example, direct, indirect, and/or combination heating methods.
In situ retorting typically involves retorting oil shale without removing the oil shale from the ground by mining. xe2x80x9cModifiedxe2x80x9d in situ processes typically require some mining to develop underground retort chambers. An example of a xe2x80x9cmodifiedxe2x80x9d in situ process includes a method developed by Occidental Petroleum that involves mining approximately 20% of the oil shale in a formation, explosively rubblizing the remainder of the oil shale to fill up the mined out area, and combusting the oil shale by gravity stable combustion in which combustion is initiated from the top of the retort. Other examples of xe2x80x9cmodifiedxe2x80x9d in situ processes include the xe2x80x9cRubble In Situ Extractionxe2x80x9d (xe2x80x9cRISExe2x80x9d) method developed by the Lawrence Livermore Laboratory (xe2x80x9cLLLxe2x80x9d) and radio-frequency methods developed by IIT Research Institute (xe2x80x9cIITRIxe2x80x9d) and LLL, which involve tunneling and mining drifts to install an array of radio-frequency antennas in an oil shale formation.
Obtaining permeability within an oil shale formation (e.g., between injection and production wells) tends to be difficult because oil shale is often substantially impermeable. Many methods have attempted to link injection and production wells, including: hydraulic fracturing such as methods investigated by Dow Chemical and Laramie Energy Research Center; electrical fracturing (e.g., by methods investigated by Laramie Energy Research Center); acid leaching of limestone cavities (e.g., by methods investigated by Dow Chemical); steam injection into permeable nahcolite zones to dissolve the nahcolite (e.g., by methods investigated by Shell Oil and Equity Oil); fracturing with chemical explosives (e.g., by methods investigated by Talley Energy Systems); fracturing with nuclear explosives (e.g., by methods investigated by Project Bronco); and combinations of these methods. Many of such methods, however, have relatively high operating costs and lack sufficient injection capacity.
An example of an in situ retorting process is illustrated in U.S. Pat. No. 3,241,611 to Dougan, assigned to Equity Oil Company, which is incorporated by reference as if fully set forth herein. For example, Dougan discloses a method involving the use of natural gas for conveying kerogen-decomposing heat to the formation. The heated natural gas may be used as a solvent for thermally decomposed kerogen. The heated natural gas exercises a solvent-stripping action with respect to the oil shale by penetrating pores that exist in the shale. The natural gas carrier fluid, accompanied by decomposition product vapors and gases, passes upwardly through extraction wells into product recovery lines, and into and through condensers interposed in such lines, where the decomposition vapors condense, leaving the natural gas carrier fluid to flow through a heater and into an injection well drilled into the deposit of oil shale.
Large deposits of heavy hydrocarbons (e.g., heavy oil and/or tar) contained within relatively permeable formations (e.g., in tar sands) are found in North America, South America, and Asia. Tar can be surface-mined and upgraded to lighter hydrocarbons such as crude oil, naphtha, kerosene, and/or gas oil. Tar sand deposits may, for example, first be mined. Surface milling processes may further separate the bitumen from sand. The separated bitumen may be converted to light hydrocarbons using conventional refinery methods. Mining and upgrading tar sand is usually substantially more expensive than producing lighter hydrocarbons from conventional oil reservoirs.
U.S. Pat. Nos. 5,340,467 to Gregoli et al. and 5,316,467 to Gregoli et al., which are incorporated by reference as if fully set forth herein, describe adding water and a chemical additive to tar sand to form a slurry. The slurry may be separated into hydrocarbons and water.
U.S. Pat. No. 4,409,090 to Hanson et al., which is incorporated by reference as if fully set forth herein, describes physically-separating tar sand into a bitumen-rich concentrate that may have some remaining sand. The bitumen-rich concentrate may be further separated from sand in a fluidized bed.
U.S. Pat. Nos. 5,985,138 to Humphreys and 5,968,349 to Duyvesteyn et al., which are incorporated by reference as if fully set forth herein, describe mining tar sand and physically separating bitumen from the tar sand. Further processing of bitumen in surface facilities may upgrade oil produced from bitumen.
In situ production of hydrocarbons from tar sand may be accomplished by heating and/or injecting a gas into the formation. U.S. Pat. Nos. 5,211,230 to Ostapovich et al. and 5,339,897 to Leaute, which are incorporated by reference as if fully set forth herein, describe a horizontal production well located in an oil-bearing reservoir. A vertical conduit may be used to inject an oxidant gas into the reservoir for in situ combustion.
U.S. Pat. No. 2,780,450 to Ljungstrom, which is incorporated by reference as if fully set forth herein, describes heating bituminous geological formations in situ to convert or crack a liquid tar-like substance into oils and gases.
U.S. Pat. No. 4,597,441 to Ware et al, which is incorporated by reference as if fully set forth herein, describes contacting oil, heat, and hydrogen simultaneously in a reservoir. Hydrogenation may enhance recovery of oil from the reservoir.
U.S. Pat. Nos. 5,046,559 to Glandt and 5,060,726 to Glandt et al, which are incorporated by reference as if fully set forth herein, describe preheating a portion of a tar sand formation between an injector well and a producer well. Steam may be injected from the injector well into the formation to produce hydrocarbons at the producer well.
Substantial reserves of heavy hydrocarbons are known to exist in formations that have relatively low permeability. For example, billions of barrels of oil reserves are known to exist in diatomaceous formations in California. Several methods have been proposed and/or used for producing heavy hydrocarbons from relatively low permeability formations.
U.S. Pat. No. 5,415,231 to Northrop et al., which is incorporated by reference as if fully set forth herein, describes a method for recovering hydrocarbons (e.g. oil) from a low permeability subterranean reservoir of the type comprised primarily of diatomite. A first slug or volume of a heated fluid (e.g. 60% quality steam) is injected into the reservoir at a pressure greater than the fracturing pressure of the reservoir. The well is then shut in and the reservoir is allowed to soak for a prescribed period (e.g. 10 days or more) to allow the oil to be displaced by the steam into the fractures. The well is then produced until the production rate drops below an economical level. A second slug of steam is then injected and the cycles are repeated.
U.S. Pat. No. 4,530,401 to Hartman et al., which is incorporated by reference as if fully set forth herein, describes a method for the recovery of viscous oil from a subterranean, viscous oil-containing formation by injecting steam into the formation.
U.S. Pat. No. 5,339,897 to Leaute et al., which is incorporated by reference as if fully set forth herein, describes a method and apparatus for recovering and/or upgrading hydrocarbons utilizing in situ combustion and horizontal wells.
U.S. Pat. No. 5,431,224 to Laali, which is incorporated by reference as if fully set forth herein, describes a method for improving hydrocarbon flow from low permeability tight reservoir rock.
U.S. Pat. Nos. 5,297,626 Vinegar et al. and 5,392,854 to Vinegar et al., which are incorporated by reference as if fully set forth herein, describe a process wherein an oil containing subterranean formation is heated.
As outlined above, there has been a significant amount of effort to develop methods and systems to economically produce hydrocarbons, hydrogen, and/or other products from hydrocarbon containing formations. At present, however, there are still many hydrocarbon containing formations from which hydrocarbons, hydrogen, and/or other products cannot be economically produced. Thus, there is still a need for improved methods and systems for production of hydrocarbons, hydrogen, and/or other products from various hydrocarbon containing formations.
In an embodiment, hydrocarbons within a hydrocarbon containing formation (e.g., a formation containing coal, oil shale, heavy hydrocarbons, or a combination thereof) may be converted in situ within the formation to yield a mixture of relatively high quality hydrocarbon products, hydrogen, and other products. One or more heat sources may be used to heat a portion of the hydrocarbon containing formation to temperatures that allow pyrolysis of the hydrocarbons. Hydrocarbons, hydrogen, and other formation fluids may be removed from the formation through one or more production wells. The formation fluids may be removed in a vapor phase. Temperature and pressure in at least a portion of the formation may be controlled during pyrolysis to yield improved products from the formation.
A heated formation may also be used to produce synthesis gas. In certain embodiments synthesis gas is produced after production of pyrolysis fluids.
A formation may be heated to a temperature greater than 400xc2x0 C. prior to contacting a synthesis gas generating fluid with the formation. Contacting a synthesis gas generating fluid, such as water, steam, and/or carbon dioxide, with carbon and/or hydrocarbons within the formation results in generation of synthesis gas if the temperature of the carbon is sufficiently high. Synthesis gas generation is, in some embodiments, an endothermic process. Additional heat may be added to the formation during synthesis gas generation to maintain a high temperature within the formation. The heat may be added from heater wells and/or from oxidizing carbon and/or hydrocarbons within the formation. The generated synthesis gas may be removed from the formation through one or more production wells.
After production of pyrolysis fluids and/or synthesis gas, fluid may be sequestered within the formation. To store a significant amount of fluid within the formation, a temperature of the formation will often need to be less than about 100xc2x0 C. Water may be introduced into at least a portion of the formation to generate steam and reduce a temperature of the formation. The steam may be removed from the formation. The steam may be utilized for various purposes, including, but not limited to, heating another portion of the formation, generating synthesis gas in an adjacent portion of the formation, generating electricity, and/or as a steam flood in a oil reservoir. After the formation is cooled, fluid (e.g., carbon dioxide) may be pressurized and sequestered in the formation. Sequestering fluid within the formation may result in a significant reduction or elimination of fluid that is released to the environment due to operation of the in situ conversion process.
In an embodiment, one or more heat sources may be installed into a formation to heat the formation. Heat sources may be installed by drilling openings (well bores) into the formation. In some embodiments openings may be formed in the formation using a drill with a steerable motor and an accelerometer. Alternatively, an opening may be formed into the formation by geosteered drilling. Alternately, an opening may be formed into the formation by sonic drilling.
One or more heat sources may be disposed within the opening such that the heat source may be configured to transfer heat to the formation. For example, a heat source may be placed in an open wellbore in the formation. In this manner, heat may conductively and radiatively transfer from the heat source to the formation. Alternatively, a heat source may be placed within a heater well that may be packed with gravel, sand, and/or cement. The cement may be a refractory cement.
In some embodiments one or more heat sources may be placed in a pattern within the formation. For example, in one embodiment, an in situ conversion process for hydrocarbons may include heating at least a portion of a hydrocarbon containing formation with an array of heat sources disposed within the formation. In some embodiments, the array of heat sources can be positioned substantially equidistant from a production well. Certain patterns (e.g., triangular arrays, hexagonal arrays, or other array patterns) may be more desirable for specific applications. In addition, the array of heat sources may be disposed such that a distance between each heat source may be less than about 70 feet (21 m). In addition, the in situ conversion process for hydrocarbons may include heating at least a portion of the formation with heat sources disposed substantially parallel to a boundary of the hydrocarbons. Regardless of the arrangement of or distance between the heat sources, in certain embodiments, a ratio of heat sources to production wells disposed within a formation may be greater than about 5, 8, 10, 20, or more.
Certain embodiments may also include allowing heat to transfer from one or more of the heat sources to a selected section of the heated portion. In an embodiment, the selected section may be disposed between one or more heat sources. For example, the in situ conversion process may also include allowing heat to transfer from one or more heat sources to a selected section of the formation such that heat from one or more of the heat sources pyrolyzes at least some hydrocarbons within the selected section. In this manner, the in situ conversion process may include heating at least a portion of a hydrocarbon containing formation above a pyrolyzation temperature of hydrocarbons in the formation. For example, a pyrolyzation temperature may include a temperature of at least about 270xc2x0 C. Heat may be allowed to transfer from one or more of the heat sources to the selected section substantially by conduction.
One or more heat sources may be located within the formation such that superposition of heat produced from one or more heat sources may occur. Superposition of heat may increase a temperature of the selected section to a temperature sufficient for pyrolysis of at least some of the hydrocarbons within the selected section. Superposition of heat may vary depending on, for example, a spacing between heat sources. The spacing between heat sources may be selected to optimize heating of the section selected for treatment. Therefore, hydrocarbons may be pyrolyzed within a larger area of the portion. In this manner, spacing between heat sources may be selected to increase the effectiveness of the heat sources, thereby increasing the economic viability of a selected in situ conversion process for hydrocarbons. Superposition of heat tends to increase the uniformity of heat distribution in the section of the formation selected for treatment.
Various systems and methods may be used to provide heat sources. In an embodiment, a natural distributed combustor system and method may be configured to heat at least a portion of a hydrocarbon containing formation. The system and method may first include heating a first portion of the formation to a temperature sufficient to support oxidation of at least some of the hydrocarbons therein. One or more conduits may be disposed within one or more openings. One or more of the conduits may be configured to provide an oxidizing fluid from an oxidizing fluid source into an opening in the formation. The oxidizing fluid may oxidize at least a portion of the hydrocarbons at a reaction zone within the formation. Oxidation may generate heat at the reaction zone. The generated heat may transfer from the reaction zone to a pyrolysis zone in the formation. The heat may transfer by conduction, radiation, and/or convection. In this manner, a heated portion of the formation may include the reaction zone and the pyrolysis zone. The heated portion may also be located substantially adjacent to the opening. One or more of the conduits may also be configured to remove one or more oxidation products from the reaction zone and/or formation. Alternatively, additional conduits may be configured to remove one or more oxidation products from the reaction zone and/or formation.
In an embodiment, a system and method configured to heat a hydrocarbon containing formation may include one or more insulated conductors disposed in one or more openings in the formation. The openings may be uncased. Alternatively, the openings may include a casing. As such, the insulated conductors may provide conductive, radiant, or convective heat to at least a portion of the formation. In addition, the system and method may be configured to allow heat to transfer from the insulated conductor to a section of the formation. In some embodiments, the insulated conductor may include a copper-nickel alloy. In some embodiments, the insulated conductor may be electrically coupled to two additional insulated conductors in a 3-phase Y configuration.
In an embodiment, a system and method may include one or more elongated members disposed in an opening in the formation. Each of the elongated members may be configured to provide heat to at least a portion of the formation. One or more conduits may be disposed in the opening. One or more of the conduits may be configured to provide an oxidizing fluid from an oxidizing fluid source into the opening. In certain embodiments, the oxidizing fluid may be configured to substantially inhibit carbon deposition on or proximate to the elongated member.
In an embodiment, a system and method for heating a hydrocarbon containing formation may include oxidizing a fuel fluid in a heater. The method may further include providing at least a portion of the oxidized fuel fluid into a conduit disposed in an opening in the formation. In addition, additional heat may be transferred from an electric heater disposed in the opening to the section of the formation. Heat may be allowed to transfer substantially uniformly along a length of the opening.
Energy input costs may be reduced in some embodiments of systems and methods described above. For example, an energy input cost may be reduced by heating a portion of a hydrocarbon containing formation by oxidation in combination with heating the portion of the formation by an electric heater. The electric heater may be turned down and/or off when the oxidation reaction begins to provide sufficient heat to the formation. In this manner, electrical energy costs associated with heating at least a portion of a formation with an electric heater may be reduced. Thus, a more economical process may be provided for heating a hydrocarbon containing formation in comparison to heating by a conventional method. In addition, the oxidation reaction may be propagated slowly through a greater portion of the formation such that fewer heat sources may be required to heat such a greater portion in comparison to heating by a conventional method.
Certain embodiments as described herein may provide a lower cost system and method for heating a hydrocarbon containing formation. For example, certain embodiments may provide substantially uniform heat transfer along a length of a heater. Such a length of a heater may be greater than about 300 m or possibly greater than about 600 m. In addition, in certain embodiments, heat may be provided to the formation more efficiently by radiation. Furthermore, certain embodiments of systems as described herein may have a substantially longer lifetime than presently available systems.
In an embodiment, an in situ conversion system and method for hydrocarbons may include maintaining a portion of the formation in a substantially unheated condition. In this manner, the portion may provide structural strength to the formation and/or confinement/isolation to certain regions of the formation. A processed hydrocarbon containing formation may have alternating heated and substantially unheated portions arranged in a pattern that may, in some embodiments, resemble a checkerboard pattern, or a pattern of alternating areas (e.g., strips) of heated and unheated portions.
In an embodiment, a heat source may advantageously heat only along a selected portion or selected portions of a length of the heater. For example, a formation may include several hydrocarbon containing layers. One or more of the hydrocarbon containing layers may be separated by layers containing little or no hydrocarbons. A heat source may include several discrete high heating zones that may be separated by low heating zones. The high heating zones may be disposed proximate hydrocarbon containing layers such that the layers may be heated. The low heating zones may be disposed proximate to layers containing little or no hydrocarbons such that the layers may not be substantially heated. For example, an electrical heater may include one or more low resistance heater sections and one or more high resistance heater sections. In this manner, low resistance heater sections of the electrical heater may be disposed in and/or proximate to layers containing little or no hydrocarbons. In addition, high resistance heater sections of the electrical heater may be disposed proximate hydrocarbon containing layers. In an additional example, a fueled heater (e.g., surface burner) may include insulated sections. In this manner, insulated sections of the fueled heater may be placed proximate to or adjacent to layers containing little or no hydrocarbons. Alternately, a heater with distributed air and/or fuel may be configured such that little or no fuel may be combusted proximate to or adjacent to layers containing little or no hydrocarbons. Such a fueled heater may include flameless combustors and natural distributed combustors.
In an embodiment, a heating rate of the formation may be slowly raised through the pyrolysis temperature range. For example, an in situ conversion process for hydrocarbons may include heating at least a portion of a hydrocarbon containing formation to raise an average temperature of the portion above about 270xc2x0 C. by a rate less than a selected amount (e.g., about 10xc2x0 C., 5xc2x0 C., 3xc2x0 C., 1xc2x0 C., 0.5xc2x0 C., or 0.1xc2x0 C.) per day. In a further embodiment, the portion may be heated such that an average temperature of the selected section may be less than about 375xc2x0 C. or, in some embodiments, less than about 400xc2x0 C.
In an embodiment, a temperature of the portion may be monitored through a test well disposed in a formation. For example, the test well may be positioned in a formation between a first heat source and a second heat source. Certain systems and methods may include controlling the heat from the first heat source and/or the second heat source to raise the monitored temperature at the test well at a rate of less than about a selected amount per day. In addition or alternatively, a temperature of the portion may be monitored at a production well. In this manner, an in situ conversion process for hydrocarbons may include controlling the heat from the first heat source and/or the second heat source to raise the monitored temperature at the production well at a rate of less than a selected amount per day.
Certain embodiments may include heating a selected volume of a hydrocarbon containing formation. Heat may be provided to the selected volume by providing power to one or more heat sources. Power may be defined as heating energy per day provided to the selected volume. A power (Pwr) required to generate a heating rate (h, in units of, for example, xc2x0 C./day) in a selected volume (V) of a hydrocarbon containing formation may be determined by the following equation: Pwr=h*V*Cv*xcfx81B. In this equation, an average heat capacity of the formation (Cv) and an average bulk density of the formation (xcfx81B) may be estimated or determined using one or more samples taken from the hydrocarbon containing formation.
Certain embodiments may include raising and maintaining a pressure in a hydrocarbon containing formation. Pressure may be, for example, controlled within a range of about 2 bars absolute to about 20 bars absolute. For example, the process may include controlling a pressure within a majority of a selected section of a heated portion of the formation. The controlled pressure may be above about 2 bars absolute during pyrolysis. In an alternate embodiment, an in situ conversion process for hydrocarbons may include raising and maintaining the pressure in the formation within a range of about 20 bars absolute to about 36 bars absolute.
In an embodiment, compositions and properties of formation fluids produced by an in situ conversion process for hydrocarbons may vary depending on, for example, conditions within a hydrocarbon containing formation.
Certain embodiments may include controlling the heat provided to at least a portion of the formation such that production of less desirable products in the portion may be substantially inhibited. Controlling the heat provided to at least a portion of the formation may also increase the uniformity of permeability within the formation. For example, controlling the heating of the formation to inhibit production of less desirable products may, in some embodiments, include controlling the heating rate to less than a selected amount (e.g., 10xc2x0 C., 5xc2x0 C., 3xc2x0 C., 1xc2x0 C., 0.5xc2x0 C., or 0.1xc2x0 C.) per day.
Controlling pressure, heat and/or heating rates of a selected section in a formation may increase production of selected formation fluids. For example, the amount and/or rate of heating may be controlled to produce formation fluids having an American Petroleum Institute (xe2x80x9cAPIxe2x80x9d) gravity greater than about 25. Heat and/or pressure may be controlled to inhibit production of olefins in the produced fluids.
Controlling formation conditions to control the pressure of hydrogen in the produced fluid may result in improved qualities of the produced fluids. In some embodiments it may be desirable to control formation conditions so that the partial pressure of hydrogen in a produced fluid is greater than about 0.5 bars absolute, as measured at a production well.
In an embodiment, operating conditions may be determined by measuring at least one property of the formation. At least the measured properties may be input into a computer executable program. At least one property of formation fluids selected to be produced from the formation may also be input into the computer executable program. The program may be operable to determine a set of operating conditions from at least the one or more measured properties. The program may also be configured to determine the set of operating conditions from at least one property of the selected formation fluids. In this manner, the determined set of operating conditions may be configured to increase production of selected formation fluids from the formation.
Certain embodiments may include altering a composition of formation fluids produced from a hydrocarbon containing formation by altering a location of a production well with respect to a heater well. For example, a production well may be located with respect to a heater well such that a non-condensable gas fraction of produced hydrocarbon fluids may be larger than a condensable gas fraction of the produced hydrocarbon fluids.
Condensable hydrocarbons produced from the formation will typically include paraffins, cycloalkanes, mono-aromatics, and di-aromatics as major components. Such condensable hydrocarbons may also include other components such as tri-aromatics, etc.
In certain embodiments, a majority of the hydrocarbons in produced fluid may have a carbon number of less than approximately 25. Alternatively, less than about 15 weight % of the hydrocarbons in the fluid may have a carbon number greater than approximately 25. In other embodiments fluid produced may have a weight ratio of hydrocarbons having carbon numbers from 2 through 4, to methane, of greater than approximately 1 (e.g., for oil shale and heavy hydrocarbons) or greater than approximately 0.3 (e.g., for coal). The non-condensable hydrocarbons may include, but are not limited to, hydrocarbons having carbon numbers less than 5.
In certain embodiments, the API gravity of the hydrocarbons in produced fluid may be approximately 25 or above (e.g., 30, 40, 50, etc.). In certain embodiments, the hydrogen to carbon atomic ratio in produced fluid may be at least approximately 1.7 (e.g., 1.8, 1.9, etc.).
In certain embodiments, (e.g., when the formation includes coal) fluid produced from a formation may include oxygenated hydrocarbons. In an example, the condensable hydrocarbons may include an amount of oxygenated hydrocarbons greater than about 5% by weight of the condensable hydrocarbons.
Condensable hydrocarbons of a produced fluid may also include olefins. For example, the olefin content of the condensable hydrocarbons may be from about 0.1% by weight to about 15% by weight. Alternatively, the olefin content of the condensable hydrocarbons may be from about 0.1% by weight to about 2.5% by weight or, in some embodiments less than about 5% by weight.
Non-condensable hydrocarbons of a produced fluid may also include olefins. For example, the olefin content of the non-condensable hydrocarbons may be gauged using the ethene/ethane molar ratio. In certain embodiments the ethene/ethane molar ratio may range from about 0.001 to about 0.15.
Fluid produced from the formation may include aromatic compounds. For example, the condensable hydrocarbons may include an amount of aromatic compounds greater than about 20% or about 25% by weight of the condensable hydrocarbons. The condensable hydrocarbons may also include relatively low amounts of compounds with more than two rings in them (e.g., tri-aromatics or above). For example, the condensable hydrocarbons may include less than about 1%, 2%, or about 5% by weight of tri-aromatics or above in the condensable hydrocarbons.
In particular, in certain embodiments asphaltenes (i.e., large multi-ring aromatics that are substantially insoluble in hydrocarbons) make up less than about 0.1% by weight of the condensable hydrocarbons. For example, the condensable hydrocarbons may include an asphaltene component of from about 0.0% by weight to about 0.1% by weight or, in some embodiments, less than about 0.3% by weight.
Condensable hydrocarbons of a produced fluid may also include relatively large amounts of cycloalkanes. For example, the condensable hydrocarbons may include a cycloalkane component of up to 30% by weight (e.g., from about 5% by weight to about 30% by weight) of the condensable hydrocarbons.
In certain embodiments, the condensable hydrocarbons of the fluid produced from a formation may include compounds containing nitrogen. For example, less than about 1% by weight (when calculated on an elemental basis) of the condensable hydrocarbons is nitrogen (e.g., typically the nitrogen is in nitrogen containing compounds such as pyridines, amines, amides, etc.).
In certain embodiments, the condensable hydrocarbons of the fluid produced from a formation may include compounds containing oxygen. For example, in certain embodiments (e.g., for oil shale and heavy hydrocarbons) less than about 1% by weight (when calculated on an elemental basis) of the condensable hydrocarbons is oxygen (e.g., typically the oxygen is in oxygen containing compounds such as phenols, substituted phenols, ketones, etc.). In certain other embodiments (e.g., for coal) between about 5% and about 30% by weight of the condensable hydrocarbons are typically oxygen containing compounds such as phenols, substituted phenols, ketones, etc. In some instances certain compounds containing oxygen (e.g., phenols) may be valuable and, as such, may be economically separated from the produced fluid.
In certain embodiments, the condensable hydrocarbons of the fluid produced from a formation may include compounds containing sulfur. For example, less than about 1% by weight (when calculated on an elemental basis) of the condensable hydrocarbons is sulfur (e.g., typically the sulfur is in sulfur containing compounds such as thiophenes, mercaptans, etc.).
Furthermore, the fluid produced from the formation may include ammonia (typically the ammonia condenses with the water, if any, produced from the formation). For example, the fluid produced from the formation may in certain embodiments include about 0.05% or more by weight of ammonia. Certain formations may produce larger amounts of ammonia (e.g., up to about 10% by weight of the total fluid produced may be ammonia).
Furthermore, a produced fluid from the formation may also include molecular hydrogen (H2), water, carbon dioxide, hydrogen sulfide, etc. For example, the fluid may include a H2 content between about 10% to about 80% by volume of the non-condensable hydrocarbons.
Certain embodiments may include heating to yield at least about 15% by weight of a total organic carbon content of at least some of the hydrocarbon containing formation into formation fluids.
In an embodiment, an in situ conversion process for treating a hydrocarbon containing formation may include providing heat to a section of the formation to yield greater than about 60% by weight of the potential hydrocarbon products and hydrogen, as measured by the Fischer Assay.
In certain embodiments, heating of the selected section of the formation may be controlled to pyrolyze at least about 20% by weight (or in some embodiments about 25% by weight) of the hydrocarbons within the selected section of the formation.
Certain embodiments may include providing a reducing agent to at least a portion of the formation. A reducing agent provided to a portion of the formation during heating may increase production of selected formation fluids. A reducing agent may include, but is not limited to, molecular hydrogen. For example, pyrolyzing at least some hydrocarbons in a hydrocarbon containing formation may include forming hydrocarbon fragments. Such hydrocarbon fragments may react with each other and other compounds present in the formation. Reaction of these hydrocarbon fragments may increase production of olefin and aromatic compounds from the formation. Therefore, a reducing agent provided to the formation may react with hydrocarbon fragments to form selected products and/or inhibit the production of non-selected products.
In an embodiment, a hydrogenation reaction between a reducing agent provided to a hydrocarbon containing formation and at least some of the hydrocarbons within the formation may generate heat. The generated heat may be allowed to transfer such that at least a portion of the formation may be heated. A reducing agent such as molecular hydrogen may also be autogenously generated within a portion of a hydrocarbon containing formation during an in situ conversion process for hydrocarbons. In this manner, the autogenously generated molecular hydrogen may hydrogenate formation fluids within the formation. Allowing formation waters to contact hot carbon in the spent formation may generate molecular hydrogen. Cracking an injected hydrocarbon fluid may also generate molecular hydrogen.
Certain embodiments may also include providing a fluid produced in a first portion of a hydrocarbon containing formation to a second portion of the formation. In this manner, a fluid produced in a first portion of a hydrocarbon containing formation may be used to produce a reducing environment in a second portion of the formation. For example, molecular hydrogen generated in a first portion of a formation may be provided to a second portion of the formation. Alternatively, at least a portion of formation fluids produced from a first portion of the formation may be provided to a second portion of the formation to provide a reducing environment within the second portion. The second portion of the formation may be treated according to any of the embodiments described herein.
Certain embodiments may include controlling heat provided to at least a portion of the formation such that a thermal conductivity of the portion may be increased to greater than about 0.5 W/(mxc2x0 C.) or, in some embodiments, greater than about 0.6 W/(m xc2x0 C.).
In certain embodiments a mass of at least a portion of the formation may be reduced due, for example, to the production of formation fluids from the formation. As such, a permeability and porosity of at least a portion of the formation may increase. In addition, removing water during the heating may also increase the permeability and porosity of at least a portion of the formation.
Certain embodiments may include increasing a permeability of at least a portion of a hydrocarbon containing formation to greater than about 0.01, 0.1, 1, 10, 20 and/or 50 Darcy. In addition, certain embodiments may include substantially uniformly increasing a permeability of at least a portion of a hydrocarbon containing formation. Some embodiments may include increasing a porosity of at least a portion of a hydrocarbon containing formation substantially uniformly.
In certain embodiments, after pyrolysis of a portion of a formation, synthesis gas may be produced from carbon and/or hydrocarbons remaining within the formation. Pyrolysis of the portion may produce a relatively high, substantially uniform permeability throughout the portion. Such a relatively high, substantially uniform permeability may allow generation of synthesis gas from a significant portion of the formation at relatively low pressures. The portion may also have a large surface area and/or surface area/volume. The large surface area may allow synthesis gas producing reactions to be substantially at equilibrium conditions during synthesis gas generation. The relatively high, substantially uniform permeability may result in a relatively high recovery efficiency of synthesis gas, as compared to synthesis gas generation in a hydrocarbon containing formation that has not been so treated.
Synthesis gas may be produced from the formation prior to or subsequent to producing a formation fluid from the formation. For example, synthesis gas generation may be commenced before and/or after formation fluid production decreases to an uneconomical level. In this manner, heat provided to pyrolyze hydrocarbons within the formation may also be used to generate synthesis gas. For example, if a portion of the formation is at a temperature from approximately 270xc2x0 C. to approximately 375xc2x0 C. (or 400xc2x0 C. in some embodiments) after pyrolyzation, then less additional heat is generally required to heat such portion to a temperature sufficient to support synthesis gas generation.
Pyrolysis of at least some hydrocarbons may in some embodiments convert about 15% by weight or more of the carbon initially available. Synthesis gas generation may convert approximately up to an additional 80% by weight or more of carbon initially available within the portion. In this manner, in situ production of synthesis gas from a hydrocarbon containing formation may allow conversion of larger amounts of carbon initially available within the portion. The amount of conversion achieved may, in some embodiments, be limited by subsidence concerns.
Certain embodiments may include providing heat from one or more heat sources to heat the formation to a temperature sufficient to allow synthesis gas generation (e.g., in a range of approximately 400xc2x0 C. to approximately 1200xc2x0 C. or higher). At a lower end of the temperature range, generated synthesis gas may have a high hydrogen (H2) to carbon monoxide (CO) ratio. At an upper end of the temperature range, generated synthesis gas may include mostly H2 and CO in lower ratios (e.g., approximately a 1:1 ratio).
Heat sources for synthesis gas production may include any of the heat sources as described in any of the embodiments set forth herein. Alternatively, heating may include transferring heat from a heat transfer fluid (e.g., steam or combustion products from a burner) flowing within a plurality of wellbores within the formation.
A synthesis gas generating fluid (e.g., liquid water, steam, carbon dioxide, air, oxygen, hydrocarbons, and mixtures thereof) may be provided to the formation. For example, the synthesis gas generating fluid mixture may include steam and oxygen. In an embodiment, a synthesis gas generating fluid may include aqueous fluid produced by pyrolysis of at least some hydrocarbons within one or more other portions of the formation. Providing the synthesis gas generating fluid may alternatively include raising a water table of the formation to allow water to flow into it. Synthesis gas generating fluid may also be provided through at least one injection wellbore. The synthesis gas generating fluid will generally react with carbon in the formation to form H2, water, methane, CO2, and/or CO. A portion of the carbon dioxide may react with carbon in the formation to generate carbon monoxide. Hydrocarbons such as ethane may be added to a synthesis gas generating fluid. When introduced into the formation, the hydrocarbons may crack to form hydrogen and/or methane. The presence of methane in produced synthesis gas may increase the heating value of the produced synthesis gas.
Synthesis gas generating reactions are typically endothermic reactions. In an embodiment, an oxidant may be added to a synthesis gas generating fluid. The oxidant may include, but is not limited to, air, oxygen enriched air, oxygen, hydrogen peroxide, other oxidizing fluids, or combinations thereof. The oxidant may react with carbon within the formation to exothermically generate heat. Reaction of an oxidant with carbon in the formation may result in production of CO2 and/or CO. Introduction of an oxidant to react with carbon in the formation may economically allow raising the formation temperature high enough to result in generation of significant quantities of H2 and CO from hydrocarbons within the formation. Synthesis gas generation may be via a batch process or a continuous process, as is further described herein.
Synthesis gas may be produced from one or more producer wells that include one or more heat sources. Such heat sources may operate to promote production of the synthesis gas with a desired composition.
Certain embodiments may include monitoring a composition of the produced synthesis gas, and then controlling heating and/or controlling input of the synthesis gas generating fluid to maintain the composition of the produced synthesis gas within a desired range. For example, in some embodiments (e.g., such as when the synthesis gas will be used as a feedstock for a Fischer-Tropsch process) a desired composition of the produced synthesis gas may have a ratio of hydrogen to carbon monoxide of about 1.8:1 to 2.2:1 (e.g., about 2:1 or about 2.1:1). In some embodiments (such as when the synthesis gas will be used as a feedstock to make methanol) such ratio may be about 3:1 (e.g., about 2.8:1 to 3.2:1).
Certain embodiments may include blending a first synthesis gas with a second synthesis gas to produce synthesis gas of a desired composition. The first and the second synthesis gases may be produced from different portions of the formation.
Synthesis gases described herein may be converted to heavier condensable hydrocarbons. For example, a Fischer-Tropsch hydrocarbon synthesis process may be configured to convert synthesis gas to branched and unbranched paraffins. Paraffins produced from the Fischer-Tropsch process may be used to produce other products such as diesel, jet fuel, and naphtha products. The produced synthesis gas may also be used in a catalytic methanation process to produce methane. Alternatively, the produced synthesis gas may be used for production of methanol, gasoline and diesel fuel, ammonia, and middle distillates. Produced synthesis gas may be used to heat the formation as a combustion fuel. Hydrogen in produced synthesis gas may be used to upgrade oil.
Synthesis gas may also be used for other purposes. Synthesis gas may be combusted as fuel. Synthesis gas may also be used for synthesizing a wide range of organic and/or inorganic compounds such as hydrocarbons and ammonia. Synthesis gas may be used to generate electricity, by combusting it as a fuel, by reducing the pressure of the synthesis gas in turbines, and/or using the temperature of the synthesis gas to make steam (and then run turbines). Synthesis gas may also be used in an energy generation unit such as a molten carbonate fuel cell, a solid oxide fuel cell, or other type of fuel cell.
Certain embodiments may include separating a fuel cell feed stream from fluids produced from pyrolysis of at least some of the hydrocarbons within a formation. The fuel cell feed stream may include H2, hydrocarbons, and/or carbon monoxide. In addition, certain embodiments may include directing the fuel cell feed stream to a fuel cell to produce electricity. The electricity generated from the synthesis gas or the pyrolyzation fluids in the fuel cell may be configured to power electrical heaters, which may be configured to heat at least a portion of the formation. Certain embodiments may include separating carbon dioxide from a fluid exiting the fuel cell. Carbon dioxide produced from a fuel cell or a formation may be used for a variety of purposes.
In an embodiment, a portion of a formation that has been pyrolyzed and/or subjected to synthesis gas generation may be allowed to cool or may be cooled to form a cooled, spent portion within the formation. For example, a heated portion of a formation may be allowed to cool by transference of heat to adjacent portion of the formation. The transference of heat may occur naturally or may be forced by the introduction of heat transfer fluids through the heated portion and into a cooler portion of the formation. Alternatively, introducing water to the first portion of the formation may cool the first portion. Water introduced into the first portion may be removed from the formation as steam. The removed steam or hot water may be injected into a hot portion of the formation to create synthesis gas.
Cooling the formation may provide certain benefits such as increasing the strength of the rock in the formation (thereby mitigating subsidence), increasing absorptive capacity of the formation, etc.
In an embodiment, a cooled, spent portion of a hydrocarbon containing formation may be used to store and/or sequester other materials such as carbon dioxide. Carbon dioxide may be injected under pressure into the cooled, spent portion of the formation. The injected carbon dioxide may adsorb onto hydrocarbons in the formation and/or reside in void spaces such as pores in the formation. The carbon dioxide may be generated during pyrolysis, synthesis gas generation, and/or extraction of useful energy.
In an embodiment, produced formation fluids may be stored in a cooled, spent portion of the formation. In some embodiments carbon dioxide may be stored in relatively deep coal beds, and used to desorb coal bed methane.
Many of the in situ processes and/or systems described herein may be used to produce hydrocarbons, hydrogen and other formation fluids from a relatively permeable formation that includes heavy hydrocarbons (e.g., from tar sands). Heating may be used to mobilize the heavy hydrocarbons within the formation, and then to pyrolyze heavy hydrocarbons within the formation to form pyrolyzation fluids. Formation fluids produced during pyrolyzation may be removed from the formation through production wells.
In certain embodiments fluid (e.g., gas) may be provided to a relatively permeable formation. The gas may be used to pressurize the formation. A pressure in the formation may be selected to control mobilization of fluid within the formation. For example, a higher pressure may increase the mobilization of fluid within the formation such that fluids may be produced at a higher rate.
In an embodiment, a portion of a relatively permeable formation may be heated to reduce a viscosity of the heavy hydrocarbons within the formation. The reduced viscosity heavy hydrocarbons may be mobilized. The mobilized heavy hydrocarbons may flow to a selected pyrolyzation section of the formation. A gas may be provided into the relatively permeable formation to increase a flow of the mobilized heavy hydrocarbons into the selected pyrolyzation section. Such a gas may be, for example, carbon dioxide (the carbon dioxide may be stored in the formation after removal of the heavy hydrocarbons). The heavy hydrocarbons within the selected pyrolyzation section may be substantially pyrolyzed. Pyrolyzation of the mobilized heavy hydrocarbons may upgrade the heavy hydrocarbons to a more desirable product. The pyrolyzed heavy hydrocarbons may be removed from the formation through a production well. In some embodiments, the mobilized heavy hydrocarbons may be removed from the formation through a production well without upgrading or pyrolyzing the heavy hydrocarbons.
Hydrocarbon fluids produced from the formation may vary depending on conditions within the formation. For example, a heating rate of a selected pyrolyzation section may be controlled to increase the production of selected products. In addition, pressure within the formation may be controlled to vary the composition of the produced fluids.
Certain systems and methods described herein may be used to treat heavy hydrocarbons in at least a portion of a relatively low permeability formation (e.g., in xe2x80x9ctightxe2x80x9d formations that contain heavy hydrocarbons). Such heavy hydrocarbons may be heated to pyrolyze at least some of the heavy hydrocarbons in a selected section of the formation. Heating may also increase the permeability of at least a portion of the selected section. Fluids generated from pyrolysis may be produced from the formation.
Certain embodiments for treating heavy hydrocarbons in a relatively low permeability formation may include providing heat from one or more heat sources to pyrolyze some of the heavy hydrocarbons and then to vaporize a portion of the heavy hydrocarbons. The heat sources may pyrolyze at least some heavy hydrocarbons in a selected section of the formation and may pressurize at least a portion of the selected section. During the heating, the pressure within the formation may increase substantially. The pressure in the formation may be controlled such that the pressure in the formation may be maintained to produce a fluid of a desired composition. Pyrolyzation fluid may be removed from the formation as vapor from one or more heater wells by using the back pressure created by heating the formation.
Certain embodiments for treating heavy hydrocarbons in at least a portion of a relatively low permeability formation may include heating to create a pyrolysis zone and heating a selected second section to less than the average temperature within the pyrolysis zone. Heavy hydrocarbons may be pyrolyzed in the pyrolysis zone. Heating the selected second section may decrease the viscosity of some of the heavy hydrocarbons in the selected second section to create a low viscosity zone. The decrease in viscosity of the fluid in the selected second section may be sufficient such that at least some heated heavy hydrocarbons within the selected second section may flow into the pyrolysis zone. Pyrolyzation fluid may be produced from the pyrolysis zone. In one embodiment, the density of the heat sources in the pyrolysis zone may be greater than in the low viscosity zone.
In certain embodiments it may be desirable to create the pyrolysis zones and low viscosity zones sequentially over time. The heat sources in a region near a desired pyrolysis zone may be activated first, resulting in a substantially uniform pyrolysis zone that may be established after a period of time. Once the pyrolysis zone is established, heat sources in the low viscosity zone may be activated sequentially from nearest to farthest from the pyrolysis zone.